Process for dispersing nanocatalysts into petroleum-bearing formations

ABSTRACT

Embodiments of the invention provide methods for recovering petroleum products from a formation by distributing nanocatalysts into the formation and heating the heavy crude oil therein. In one embodiment, a method is provided which includes flowing a catalytic material containing the nanocatalyst into the formation containing the heavy crude oil, exposing the heavy crude oil and the catalytic material to a reducing agent (e.g., H 2 ), positioning a steam generator within the formation, generating and releasing steam from the steam generator to heat the heavy crude oil containing the catalytic material, forming lighter oil products within the formation, and extracting the lighter oil products from the formation. In another embodiment, a method is provided which includes exposing the heavy crude oil and the catalytic material to an oxidizing agent (e.g., O 2 ). The nanocatalyst may contain cobalt, iron, nickel, molybdenum, chromium, tungsten, titanium, oxides thereof, alloys thereof, derivatives thereof, or combinations thereof.

CROSS-REFERENCE TO RELATED APPLICATIONS

This patent application claims benefit to U.S. Ser. No. 60/885,442,filed Jan. 18, 2007, and is a continuation-in-part of U.S. Ser. No.11/868,707, filed Oct. 8, 2007, which claims benefit of U.S. Ser. No.60/850,181, filed Oct. 9, 2006, U.S. Ser. No. 60/857,073, filed Nov. 6,2006, and U.S. Ser. No. 60/885,442, filed Jan. 18, 2007, which areherein incorporated by reference in their entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the invention relates in general to improving theperformance of petroleum-bearing formations and, in particular, to animproved system, method, and apparatus for distributing nanocatalysts inpetroleum-bearing formations.

2. Description of the Related Art

Vast quantities of heavy oil and bitumen are found in Canada, Venezuela,and the United States. These resources of heavy oil and bitumen aretypically characterized by having low specific gravities (0-18° API),high viscosities (>100,000 cp), and high sulfur content (e.g., >5% byweight). As a result, these resources are difficult and expensive torefine into saleable products.

Pyrolysis occurs when oil thermally cracks at temperatures greater thanabout 650° F. Although pyrolysis reduces the viscosity of oil, sometimesdramatically, it often results in the formation of large quantities ofcoke. This thermal reaction also causes a desirable increase in the APIgravity, but it has little effect on the sulfur and tends to raise thetotal acid number, which sharply reduces the value of the oil torefiners. To overcome these limitations, it would be helpful to have anin situ process for upgrading the raw material before it is producedfrom the wells.

Conventional, aftermarket refining provides two alternative types ofrefining processes for the initial upgrading step: (1) carbon removal(e.g., delayed coking), or (2) hydrogen addition (e.g., hydrogenation).Delayed coking is not well-suited for in situ upgrading because of thehigh temperatures (e.g., about 900° F.-1,250° F.) and the short reactiontimes (e.g., about 2-3 hours) required to complete the process.

With regard to hydrogenation, nanocatalysts have been developed forvarious chemical reactions used in refining applications. Nanocatalystsare beneficial for upgrading, and include alkylation of aromatics overTiO₂, isomerization of alkanes over TiO₂, dehydrogenation/hydrogenationof C—H bonds over TiO₂/Pt, hydrogenation of double bonds over TiO₂/Ni,and hydro-desulfurization of thiophene over TiO₂/Ni/Mo. However, thestumbling block that prevents the application of these solutions to insitu upgrading is the lack of technique or method to inject theappropriate catalysts (e.g., nanoparticles) and then disperse themthroughout a portion of the target reservoir.

Processes for the in situ conversion and recovery of heavy crude oilsand natural bitumens from subsurface formations have been described. Amixture of reducing gases, oxidizing gases, and steam are fed todownhole combustion devices located in the injection boreholes.Alternatively, the gas mixture may be provided from the surface.Combustion of the reducing gas-oxidizing gas mixture is carried out toproduce high quality wet steam or superheated steam and hot reducinggases for injection into the formation to convert and upgrade the heavycrude or bitumen into lighter hydrocarbons. The excess reducing gas thatis not used as fuel is injected into the formation for converting oil inplace to less viscous oil and upgrading the tar. Although this solutionis beneficial for many applications, it is not suitable for introducingand distributing nanocatalysts in an oil-bearing formation.

SUMMARY OF THE INVENTION

Embodiments of the invention provide methods for recovering petroleumproducts from a petroleum-bearing formation by distributingnanocatalysts into the petroleum-bearing formation and heating the heavycrude oil therein. In one embodiment, a method for recovering petroleumproducts from a formation is provided which includes flowing a catalyticmaterial containing a nanocatalyst into the formation containing a heavycrude oil, exposing the heavy crude oil and the catalytic material to areducing agent, positioning a steam generator within the formation,generating and releasing steam from the steam generator to heat theheavy crude oil containing the catalytic material, forming lighter oilproducts from the heavy crude oil within the formation, and extractingthe lighter oil products from the formation.

In some examples, the nanocatalyst may contain iron, nickel, molybdenum,tungsten, titanium, vanadium, chromium, manganese, cobalt, alloysthereof, oxides thereof, sulfides thereof, derivatives thereof, orcombinations thereof. In one example, the nanocatalyst contains iron andanother metal, such as nickel and/or molybdenum. In another example, thenanocatalyst contains a cobalt compound and a molybdenum compound. Inanother example, the nanocatalyst contains a nickel compound and amolybdenum compound. In another example, the nanocatalyst containstungsten oxide, tungsten sulfide, derivatives thereof, or combinationsthereof. The catalytic material may contain the nanocatalyst supportedon carbon nanoparticulate or on alumina, silica, molecular sieves,ceramic materials, derivatives thereof, or combinations thereof. Thecarbon nanoparticulate and the nanocatalysts usually have a diameter ofless than 1 μm, such as within a range from about 5 nm to about 500 nm.

In other examples, the heavy crude oil containing the catalytic materialmay be heated by the steam to a temperature of less than about 600° F.,preferably, within a range from about 250° F. to about 580° F., and morepreferably, from about 400° F. to about 550° F. The reducing agent maycontain a reagent such as hydrogen gas, carbon monoxide, synthetic gas,tetralin, decalin, derivatives thereof, or combinations thereof. Inother examples, the catalytic material and the reducing agent areco-flowed into the formation. In one example, the reducing agentcontains hydrogen gas, which has a partial pressure of about 100 psi orgreater within the formation.

In another example, the steam is generated by combusting oxygen gas andhydrogen gas within the steam generator. The oxygen gas and the hydrogengas may each be transferred from outside of the formation, through aborehole, and into the formation. In another example, the steam isgenerated by combusting oxygen gas and a hydrocarbon gas within thesteam generator. The oxygen gas and the hydrocarbon gas may each betransferred from outside of the formation, through a borehole, and intothe formation. The hydrocarbon gas may contain methane. In otherexamples, the heavy crude oil and the catalytic material may be exposedto a carrier gas, such as carbon dioxide, to reduce viscosity. Carbondioxide is soluble in the heavy crude oil thereby reduces the viscosityof the heavy crude oil within the formation. The carbon dioxide may betransferred from outside of the formation, through a borehole, and intothe formation. In other examples, the recovered lighter oil productscontain a lower concentration of a sulfur impurity than the heavy crudeoil. The lighter oil products may contain about 30% by weight lesssulfur impurities than the heavy crude oil, preferably, about 50% byweight less sulfur impurities than the heavy crude oil.

In another embodiment, a method for recovering petroleum products from apetroleum-bearing formation is provided which includes flowing acatalytic material containing a nanocatalyst into a formation having aheavy crude oil, exposing the heavy crude oil and the catalytic materialto an oxidizing agent, positioning a steam generator within theformation, generating and releasing steam from the steam generator toheat the heavy crude oil containing the catalytic material, forminglighter oil products from the heavy crude oil within the formation, andextracting the lighter oil products from the formation.

In some examples, the nanocatalyst contains titanium, zirconium,aluminum, silicon, oxides thereof, alloys thereof, derivatives thereof,or combinations thereof. In one example, the nanocatalyst containstitanium oxide or derivatives thereof. In other examples, the catalyticmaterial contains the nanocatalyst supported on carbon nanotubes or onalumina, silica, molecular sieves, ceramic materials, derivativesthereof, or combinations thereof.

In other examples, the heavy crude oil containing the catalyticmaterial, that is, the nanocatalyst heavy oil mixture, may be heated bythe steam to a temperature of less than about 600° F., preferably,within a range from about 250° F. to about 580° F., and more preferably,from about 400° F. to about 550° F. The oxidizing agent contains areagent, such as oxygen gas, air, oxygen enriched air, hydrogen peroxidesolution, derivatives thereof, or combinations thereof. In someexamples, the catalytic material and the oxidizing agent are co-flowedinto the formation. In one example, the oxidizing agent contains oxygengas.

In another embodiment, a method for recovering petroleum products from apetroleum-bearing formation is provided which includes flowing ananocatalyst and a reducing agent into a formation containing a heavycrude oil, wherein the nanocatalyst and the heavy crude oil form ananocatalyst heavy oil mixture, positioning a steam generator within theformation, generating and releasing steam from the steam generator toheat the nanocatalyst heavy oil mixture within the formation, forminglighter oil products by hydrogenating the heavy crude oil within thenanocatalyst heavy oil mixture, and extracting the lighter oil productsfrom the formation.

In another embodiment, a method for recovering petroleum products from apetroleum-bearing formation is provided which includes flowing a carriergas through a first vessel containing a first batch of a catalyticmaterial containing a nanocatalyst within a first vessel, preparing asecond batch of the catalytic material within a second vessel, andflowing the catalytic material and the carrier gas from the first vesseland into a formation containing a heavy crude oil, wherein thenanocatalyst and the heavy crude oil form a nanocatalyst heavy oilmixture. The method further includes exposing the nanocatalyst heavy oilmixture to a reducing agent, positioning a steam generator within theformation, generating and releasing steam from the steam generator toheat the nanocatalyst heavy oil mixture within the formation, forminglighter oil products by hydrogenating the heavy crude oil within thenanocatalyst heavy oil mixture, and extracting the lighter oil productsfrom the formation. In one example, the carrier gas contains carbondioxide, which is exposed to the nanocatalyst heavy oil mixture. Thecarbon dioxide may be transferred from outside of the formation, througha borehole, and into the formation.

The method may further include preparing the second batch of thecatalytic material by combining the nanocatalyst and nanoparticulatewithin the second vessel. The nanocatalyst may contain at least onemetal, such as iron, nickel, molybdenum, tungsten, titanium, vanadium,chromium, manganese, cobalt, alloys thereof, oxides thereof, sulfidesthereof, derivatives thereof, or combinations thereof. In some examples,the nanoparticulate may contain carbon, alumina, silica, molecularsieves, ceramic materials, derivatives thereof, or combinations thereof.The nanoparticulate has a diameter of less than 1 μm, preferably, withina range from about 5 nm to about 500 nm.

In another embodiment, a method for recovering petroleum products from apetroleum-bearing formation is provided which includes flowing ananocatalyst and a reducing agent into a formation containing a heavycrude oil, wherein the nanocatalyst and the heavy crude oil form ananocatalyst heavy oil mixture, heating the nanocatalyst heavy oilmixture within the formation to a temperature of less than about 600°F., forming lighter oil products by hydrogenating the heavy crude oilwithin the nanocatalyst heavy oil mixture, and extracting the lighteroil products from the formation.

In some examples, the nanocatalyst heavy oil mixture may be heatedwithin the formation by flowing heated gas, liquid, or fluid fromoutside of the formation, through a borehole, and into the formationwhile exposing the nanocatalyst heavy oil mixture. In one example, thenanocatalyst heavy oil mixture is exposed to heated water, steam, orcombinations thereof. In other examples, the nanocatalyst heavy oilmixture is heated within the formation by at least one electric heaterpositioned within the formation. In other examples, the method furtherincludes heating the nanocatalyst heavy oil mixture within the formationby positioning a steam generator within the formation, and generatingand releasing steam from the steam generator to heat the nanocatalystheavy oil mixture within the formation. The temperature may be within arange from about 250° F. to about 580° F., preferably, within a rangefrom about 400° F. to about 550° F.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the features and advantages of theinvention, which will become apparent, are attained and can beunderstood in more detail, more particular description of the inventionbriefly summarized above may be had by reference to the embodimentsthereof that are illustrated in the appended drawings which form a partof this specification. It is to be noted, however, that the drawingsillustrate only some embodiments of the invention and therefore are notto be considered limiting of its scope as the invention may admit toother equally effective embodiments.

FIG. 1 depicts a side view of a downhole burner positioned in a wellhaving a casing and packer shown in sectional view taken along thelongitudinal axis of the casing in accordance with an embodimentdescribed herein;

FIG. 2 depicts a bottom sectional view of the assembly of FIG. 1 takenalong line 2-2 of FIG. 1 in accordance with an embodiment describedherein;

FIG. 3 depicts a plan view of a cover plate in accordance with anotherembodiment described herein;

FIG. 4 depicts a plan view of an oxidizer distribution manifold plate inaccordance with another embodiment described herein;

FIG. 5 depicts a plan view of a fuel distribution manifold plate inaccordance with another embodiment described herein;

FIG. 6 depicts a plan view of an injector face plate in accordance withanother embodiment described herein;

FIG. 7 depicts a lower isometric view of an injector in accordance withanother embodiment described herein;

FIG. 8 depicts a side view of a cooling liner in accordance with anotherembodiment described herein;

FIG. 9 depicts an enlarged sectional side view of a portion of thecooling liner containing effusion holes, as illustrated in FIG. 8, inaccordance with another embodiment described herein;

FIG. 10 depicts an enlarged sectional side view of a portion of thecooling liner of FIG. 8 illustrating a mixing hole therein, inaccordance with another embodiment described herein;

FIG. 11 depicts a bottom view of an injector face plate constructed inaccordance with another embodiment described herein; and

FIG. 12 depicts a schematic diagram of a system for introducing anddistributing nanocatalysts in oil-bearing formations, in accordance withanother embodiment described herein.

DETAILED DESCRIPTION

Although the following detailed description contains many specificdetails for purposes of illustration, anyone of ordinary skill in theart will appreciate that many variations and alterations to thefollowing details are within the scope of the invention. Accordingly,the exemplary embodiments of the invention described below are set forthwithout any loss of generality to, and without imposing limitationsthereon, the present invention.

FIG. 1 depicts a downhole burner 11 positioned in a well according to anembodiment of the invention. The well may contain various wellboreconfigurations including, for example, vertical, horizontal, SAGD, orvarious combinations thereof. One skilled in the art will recognize thatthe burner also functions as a heater for heating the fluids enteringthe formation. A casing 17 and a packer 23 are shown in cross-sectiontaken along the longitudinal axis of casing 17. Downhole burner 11includes an injector 13 and a cooling liner 15 containing a hollowcylindrical sleeve. A fuel line 19 and an oxidizer line 21 are connectedto and in fluid communication with injector 13.

A separate CO₂ line also may be utilized. The CO₂ may be injected atvarious and/or multiple locations along the liner, including at the headend, through the liner 15 or injector 13, or at the exit prior to thepacker 23, depending on the application. In the one embodiment, burner11 is enclosed within an outer shell or burner casing 22.

The burner 11 may be suspended by fuel line 19, oxidizer line 21 andsteam line 20 while being lowered down the well. In another embodiment,a shroud or string of tubing (neither shown) may suspend burner 11 byattaching to injector 13 and/or cooling liner 15. When installed, burner11 could be supported on packer 23 or casing 17. In one embodiment,burner casing 22 and burner 11 form an annular steam channel 25, whichsubstantially surrounds the exterior surfaces of injector 13 and coolingliner 15.

In operation, steam having a preferable steam quality of within a rangefrom about 50% to about 100%, or some degree of superheated steam, maybe formed at the surface of a well and fluidly communicated to steamchannel 25 at a pressure of, for example, about 1,600 psi. The steamarriving in steam channel 25 may have a steam quality of about 40% toabout 90% due to heat loss during transportation down the well. In oneembodiment, burner 11 has a power output of about 13 MMBTU/hr and isdesigned to produce about 3,200 bpd (barrels per day) of superheatedsteam (cold water equivalent) with an outlet temperature of around 700°F. at full load. Steam at lower temperatures may also be feasible.

Steam communicated to burner 11 through steam channel 25 may enterburner 11 through a plurality of holes in cooling liner 15. Combustionoccurring within cooling liner 15 heats the steam and increases itssteam quality. The heated, high-quality steam and combustion productsexit burner 11 through outlet 24. The steam and combustion products(e.g., the combusted fuel and oxidizer (e.g., products) or exhaustgases) then may enter an oil-bearing formation in order to, for example,upgrade and improve the mobility of heavy crude oils held in theformation. Those skilled in the art will recognize that burners havingthe design of burner 11 may be built to have almost any power output,and to provide almost any steam output and steam quality.

FIG. 2 depicts an upward view of the downhole burner of FIG. 1. Steamchannel 25 is formed between burner casing 22 and cooling liner wall 27of cooling liner 15. Injector face plate 29 of injector 13 (see FIG. 1)has formed therein a plurality of injection holes 31 for the injectionof fuel and oxidizer into the burner. Injector face plate 29 furtherincludes an igniter 33 for igniting fuel and oxidizer injected into theburner. Igniter 33 could be a variety of devices and it could be acatalytic device. A small gap 35 may be provided between injector faceplate 29 and cooling liner wall 27 so that steam can leak past and coolinjector face plate 29.

Embodiments of the invention are suitable for many different types andsizes of wells. For example, in one embodiment designed for use in awell having a well casing diameter of 7⅝-inches, burner casing 22 has anouter diameter of 6 inches and a wall thickness of 0.125 inches; coolingliner wall 27 has an outer diameter of 5 inches, an inner diameter of4.75 inches, and a wall thickness of 0.125 inches; injector face plate29 has a diameter of 4.65 inches; steam channel 25 has an annular widthbetween cooling liner wall 27 and burner casing 22 of 0.375 inches; andgap 35 has a width of 0.050 inches.

FIG. 11 illustrates one embodiment of the injector face plate 29.Injector face plate 29 forms part of injector 13 and includes igniter33. Fuel holes 93, 97 may be arranged in concentric rings 81, 85.Oxidizer holes 91, 95, 99, 101 also may be arranged in concentric rings79, 83, 87, 89. Fuel holes 93, 97 and oxidizer holes 91, 95, 99, 101correspond to injection holes 31 of FIG. 2. In one embodiment,concentric ring 79 has a radius of 1.75 inches, concentric ring 81 has aradius of 1.50 inches, concentric ring 83 has a radius of 1.25 inches,concentric ring 85 has a radius of 1.00 inches, concentric ring 87 has aradius of 0.75 inches, and concentric ring 89 has a radius of 0.50inches. In one embodiment, oxidizer holes 91 have a diameter of 0.056inches, oxidizer holes 95 have a diameter of 0.055 inches, oxidizerholes 99 have a diameter of 0.052 inches, oxidizer holes 101 have adiameter of 0.060 inches, and fuel holes 93, 97 have a diameter of 0.075inches.

In one embodiment, fuel holes 93, 97 and oxidizer holes 91, 95, 99, 101produce a shower head stream pattern of fuel and oxidizer rather than animpinging stream pattern or a fogging effect. Although other designs maybe used and are within the scope of embodiments herein, a shower headdesign moves the streams of fuel and oxidizer farther away from injectorface plate 29. This provides a longer stand-off distance between thehigh flame temperature of the combusting fuel and injector face plate29, which in turn helps to keep injector face plate 29 cooler.

FIG. 3 shows a cover plate 41 in accordance with an embodiment of theinvention. Cover plate 41 forms part of injector 13 and may includeoxidizer inlet 45 and alignment holes 43. FIG. 4 shows an oxidizerdistribution manifold plate 47 according to an embodiment of theinvention. Oxidizer distribution manifold plate 47 forms part ofinjector 13 and may include oxidizer manifold 49, oxidizer holes 51, andalignment holes 43.

FIG. 5 shows a fuel distribution manifold plate 53 according to anembodiment of the invention. Fuel distribution manifold plate 53 formspart of injector 13 and may include oxidizer holes 51 and alignmentholes 43. Fuel distribution manifold plate 53 also may include fuelinlet 55, fuel manifold or passages 57, and fuel holes 59. Fuel manifold57 may be formed to route fuel throughout the interior of fueldistribution manifold plate 53 as a means of cooling the plate.

FIG. 6 shows an injector face plate 29 according to an embodiment of theinvention. Injector face plate 29 forms part of injector 13 and mayinclude oxidizer holes 51, fuel holes 59, and alignment holes 43.Oxidizer holes 51 of FIG. 6 correspond to oxidizer holes 91, 95, 99, 101of FIG. 11 and fuel holes 59 of FIG. 6 correspond to fuel holes 93, 97of FIG. 11.

FIG. 7 depicts the assembled components of the injector 13 according toone embodiment of the invention. Injector 13 may be formed by the platesof FIGS. 3-6, with the alignment holes 43 located in each plate arrangedin alignment. More specifically, injector 13 may be formed by stackingcover plate 41 on top of oxidizer distribution manifold plate 47, whichis stacked on top of fuel distribution manifold plate 53, which isstacked on top of injector face plate 29. As shown in the drawing,alignment holes 43, oxidizer holes 51, and fuel holes 59 are visible onthe exterior, or bottom, side of injector face plate 29. Fuel inlet 55of fuel distribution manifold plate 53 also is visible on the side ofinjector 13. A pin may be inserted through alignment holes 43 to secureplates 29, 41, 47, 53 in alignment. Injector 13 and the plates forminginjector 13 have been simplified in FIGS. 3-7 to better illustrate therelationship of the plates and the design of the injector. Commercialembodiments of injector 13 may include a greater number of oxidizer andfuel holes, and may include plates that are relatively thinner thanthose shown in FIGS. 3-7.

FIG. 8 illustrates one embodiment of the cooling liner 15. The coolingliner 15 forms part of burner 11 as shown in FIG. 1. Injector 13 may bepositioned at the inlet, or upper end, 67 of cooling liner 15. Coolingliner 15 includes effusion cooling section 63 and effusion cooling andjet mixing section 65. In a one embodiment, section 63 extends for about7.5 inches from the bottom of injector 13 and section 65 extends forabout 10 inches from the bottom of section 63. Those skilled in the artwill recognize that other lengths for sections 63, 65 are within thescope of embodiments herein. Heated steam and combustion products exitcooling liner 15 through outlet 24.

Effusion cooling section 63 may be characterized by the inclusion of aplurality of effusion holes 71. Effusion cooling section 63 acts toinject small jets of steam along the surface of cooling liner 15, thusproviding a layer of cooler gases to protect liner 15. In oneembodiment, effusion holes 71 may be angled 20 degrees off of aninternal surface of cooling liner 15 and aimed downstream of inlet 67,as shown in FIG. 9. Angling of effusion holes 71 helps to prevent steamfrom penetrating too far into burner 11 and allows the steam to movealong the walls of liner 15 to keep it cool. The position of effusioncooling section 63 may correspond to the location of the flame positionin burner 11. In one embodiment, about 37.5% of the steam provided toburner 11 through steam channel 25 (FIG. 1) is injected by effusioncooling section 63.

Effusion cooling and jet mixing section 65 may be characterized by theinclusion of a plurality of effusion holes 71 as well as a plurality ofmixing holes 73. Mixing holes 73 are larger than effusion holes 71, asshown in FIG. 10. Furthermore, mixing holes 73 may be set at a 90 degreeangle off of an internal surface of cooling liner 15. Effusion holes 71act to cool liner 15 by directing steam along the wall of liner 15,while mixing holes 73 act to inject steam further toward the centralaxial portions of burner 11.

In another embodiment, the process further includes injecting liquidwater into the downhole burner and cooling the injector and/or linerwith the water. The water may be introduced to the well and injected innumerous ways such as those described herein.

Table 1 summarizes the qualities and placement of the holes of sections63, 65 in one embodiment. The first column defines the section ofcooling liner 15 and the second column describes the type of hole. Thethird and fourth columns describe the starting and ending position ofthe occurrence of the holes in relation to the top of section 63, whichmay correspond to the bottom surface of injector 13 (see FIG. 1). Thefifth column shows the percentage of total steam that is injectedthrough each group of holes. The sixth column includes the number ofholes while the seventh column describes the angle of injection. Theeighth column shows the maximum percentage of jet penetration of thesteam relative to the internal radius of cooling liner 15. The ninthcolumn shows the diameter of the holes in each group.

TABLE 1 Example of Cooling Liner Properties % of Number Injection RadialHole Hole Start End Total of Angle Injection Diameter Section Type(inches) (inches) Steam Holes (degrees) % (inches) Effusion Effusion0.00 3.00 15 720 20.0 3.90 0.0305 Cooling Effusion 3.00 5.00 12.5 60020.0 8.16 0.0305 Effusion 5.00 7.50 10 480 20.0 6.81 0.0305 EffusionMixing 7.50 7.50 6.5 18 90.0 74.35 0.1268 Cooling Effusion 7.50 9.50 4.8180 20.0 6.39 0.0345 and Jet Mixing 9.50 9.50 6.5 12 90.0 75.94 0.1553Mixing Effusion 9.50 11.50 4.8 180 20.0 5.39 0.0345 Mixing 11.50 11.506.5 8 90.0 79.68 0.1902 Effusion 11.50 13.50 4.8 180 20.0 4.66 0.0345Mixing 13.50 13.50 6.5 6 90.0 80.43 0.2196 Effusion 13.50 15.50 4.8 18020.0 4.10 0.0345 Mixing 15.50 15.50 6.5 5 90.0 78.24 0.2406 Effusion15.50 17.50 4.8 180 20.0 3.66 0.0345 Mixing 17.50 17.50 6 4 90.0 75.930.2584

Embodiments of the downhole burner may be operated using various fuels.In one embodiment, the burner may be fueled by hydrogen, methane,natural gas, or syngas. One type of syngas composition contains 44.65mole % CO, 47.56 mole % H₂, 6.80 mole % CO₂, 0.37 mole % CH₄, 0.12 mole% Ar, 0.29 mole % N₂, and 0.21 mole % H₂S+COS. One embodiment of theoxidizer for all the fuels includes oxygen and could be, for example,air, rich air, or pure oxygen. Although other temperatures may beemployed, an inlet temperature for the fuel is about 240° F. and aninlet temperature for the oxidant is about 186.5° F.

Table 2 summarizes the operating parameters of one embodiment of adownhole burner that is similar to that described in FIGS. 1-11. Thelisted parameters are considered separately for a downhole burneroperating on hydrogen, syngas, natural gas, and methane fuels. Otherfuels, such as liquid fuels, could be used.

TABLE 2 Downhole burner producing about 3200 bpd of steam ParameterUnits H₂—O₂ Syngas-O₂ CH₄—O₂ Power MMBTU/hr 13.0 13.0 13.0 Required FuelMass Flow lb/hr 376 3224 985 Inlet Pressure psi 1610 1680 1608 HoleDiameter inches 0.075 0.075 0.075 Number of 30 30 30 Holes Oxidizer MassFlow lb/hr 3011 2905 3939 Inlet Pressure psi 1629 1626 1648 Averageinches 0.055 0.055 0.055 Hole Diameter Number of 60 60 60 Holes

Embodiments of the downhole burner also may be operated using CO₂ as acoolant in addition to steam. CO₂ may be injected through the injectoror through the cooling liner. The power required to heat the steamincreases when diluents such as CO₂ are added. In the example of Table3, a quantity of CO₂ sufficient to result in 20 volumetric percent ofCO₂ in the exhaust stream of the burner is added downstream of theinjector. It can be seen that the increase in inlet pressures is minimalalthough the required power has increased.

TABLE 3 Downhole burner producing 3,200 bpd of steam and 20 volumetricpercent CO₂. CO₂ is added downstream of injector. Parameter Units H₂—O₂Syngas-O₂ CH₄—O₂ Power MMBTU/hr 14.7 14.1 14.3 Required Fuel Mass Flowlb/hr 427 3496 1084 Inlet Pressure psi 1614 1699 1610 Hole Diameterinches 0.075 0.075 0.075 Number of 30 30 30 Holes Oxidizer Mass Flowlb/hr 3413 3149 4335 Inlet Pressure psi 1637 1630 1658 Average inches0.055 0.055 0.055 Hole Diameter Number of 60 60 60 Holes

In the example of Table 4, a quantity of CO₂ sufficient to result in 20volumetric percent of CO₂ in the exhaust stream of the burner has beenadded through the fuel line and fuel holes of the burner. It can be seenthat the fuel inlet pressure is much higher than in the example of Table3. CO₂ also could be delivered through the oxidizer line and oxidizerholes, or a combination of delivery methods could be used. For example,the CO₂ could be delivered into burner 11 with the fuel.

In other embodiments, the diameters of the fuel and oxidizer injectors31 may differ to optimize the injector plate for a particular set ofconditions. In the present embodiment, the diameters are adequate forthe given conditions, assuming that supply pressure on the surface isincreased when necessary.

TABLE 4 Downhole burner producing 3,200 bpd of steam and 20 volumetricpercent CO₂. CO₂ is added through the fuel line and fuel holes.Parameter Units H₂—O₂ Syngas-O₂ CH₄—O₂ Diluent/Fuel 29.68 2.14 8.67 MassRatio Percent Diluent 100 100 100 in Fuel Line Percent Diluent 0 0 0 inOxidizer Line Power MMBTU/hr 14.7 14.1 14.3 Required Fuel Mass Flowlb/hr 427 3496 1084 Inlet Pressure psi 2416 2216 1988 Hole Diameterinches 0.075 0.075 0.075 Number of 30 30 30 Holes Oxidizer Mass Flowlb/hr 3413 3149 4335 Inlet Pressure psi 1637 1630 1658 Average inches0.055 0.055 0.055 Hole Diameter Number of 60 60 60 Holes

Burner 11 can be useful in numerous operations in several environments.For example, burner 11 can be used for the recovery of heavy oil, tarsands, shale oil, bitumen, and methane hydrates. Such operations withburner 11 are envisioned in situ under tundra, in land-based wells, andunder water, such as gulfs, seas, or oceans.

Embodiments of the invention have numerous advantages. The dual purposecooling/mixing liner maintains low wall temperatures and stresses, andmixes coolants with the combustion effluent. The head end section of theliner is used for transpiration cooling of the line through the use ofeffusion holes angled downstream of the injector plate. This allows forcoolant (primarily partially saturated steam at about 70% to 80% steamquality) to be injected along the walls, which maintains lowtemperatures and stress levels along liner walls, and maintains flowalong the walls and out of the combustion zone to prevent flameextinguishment.

The back end section of the liner provides jet mixing of steam (andother coolants) for the combustion effluent. The pressure differenceacross the liner provides sufficient jet penetration through largermixing holes to mix coolants into the main burner flow, and superheatthe coolant steam. The staggered hole pattern with varying sizes andmultiple axial distances promotes good mixing of the coolant andcombustion effluent prior to exhaust into the formation. A secondary useof transpiration cooling of the liner is accomplished through use ofeffusion holes angled downstream of the combustion zone to maintain lowtemperatures and stress level along liner walls in jet mixing section ofthe burner similar to transpiration cooling used in the head endsection.

Embodiments of the invention further provide coolant flexibility suchthat the liner can be used in current or modified embodiment withvarious vapor/gaseous phase coolants, including but not limited to oilproduction enhancing coolants, in addition to the primary coolant,steam. The liner maintains effectiveness as both a cooling and mixingcomponent when additional coolants are used.

The showerhead injector uses alternating rings of axial fuel andoxidizer jets to provide a uniform stable diffusion flame zone atmultiple pressures and turndown flow rates. It is designed to keep theflame zone away from injector face to prevent overheating of theinjector plate. The injector has flexibility to be used with multiplefuels and oxidizers, such as hydrogen, natural gases of variouscompositions, and syngases of various compositions, as well as mixturesof these primary fuels. The oxidizers include oxygen (e.g., about90%-95% purity) as well as air and “oxygen-rich” air for appropriateapplications. The oil production enhancing coolants (e.g., carbondioxide) can be mixed with the fuel and injected through the injectorplate.

Catalytic Material Containing Nanocatalyst

Embodiments of the invention provide methods for recovering petroleumproducts from a petroleum-bearing formation by distributingnanocatalysts into the petroleum-bearing formation and heating the heavycrude oil therein. In some embodiments, a method is provided whichincludes flowing a catalytic material containing a nanocatalyst into aformation having a heavy crude oil, exposing the heavy crude oil and thecatalytic material to a reducing agent (e.g., H₂) or an oxidizing agent(e.g., O₂), positioning a steam generator within the formation,generating and releasing steam from the steam generator to heat theheavy crude oil containing the catalytic material, forming lighter oilproducts from the heavy crude oil within the formation, and extractingthe lighter oil products from the formation.

The method may be used to disperse nanocatalysts into heavy crude oiland/or bitumen-bearing formations under conditions of time, temperature,and pressure that cause refining reactions to occur, such as thosedescribed herein. The nanocatalysts may be injected into the exhaust gasdownstream from the outlet or tailpipe of the burner via a conduit orpipe, including an optional separate line. The appropriate catalystcauses the reactions to take place at a temperature that is lower thanthe temperature of thermal (e.g., non-catalytic) reactions.Advantageously, less coke is formed at the lower temperature. In oneembodiment, a recovery process utilizing nanocatalyst as describedherein may decrease the process temperature by about 50° F. or greater,preferably, about 100° F. or greater, and more preferably, about 200° F.or greater, than a similar thermal recovery process not utilizingcatalyst within the same formation.

The heavy crude oil containing the catalytic material and containedwithin the formation may be heated to form lighter oil products byhydrogenating the heavy crude oil and extracting the lighter oilproducts from the formation. The heavy crude oil containing thecatalytic material and contained within the formation may be heated to atemperature of less than about 600° F., preferably, within a range fromabout 250° F. to about 580° F., and more preferably, from about 400° F.to about 550° F. In one example, the nanocatalyst heavy oil mixture maybe heated by steam produced from a downhole steam generator positionedwithin the formation. In another example, the nanocatalyst heavy oilmixture may be heated by steam produced above ground, flowed through theborehole, and exposed to the nanocatalyst heavy oil mixture within theformation. In another example, the nanocatalyst heavy oil mixture may beheated by at least one electric heater positioned within the formationand in physical or thermal contact with the nanocatalyst heavy oilmixture.

In another embodiment, the heavy crude oil within the formation isdesulfurized and the resulting recovered lighter oil products contain alower concentration of a sulfur impurity than the heavy crude oil.Usually, heavy crude oil found within formations may have a sulfurimpurity concentration within a range from about 2% to about 9% byweight. However, the catalytic processes described herein may beperformed within formations to produce lighter oil products having asulfur impurity concentration reduced by about 10%, preferably, about30%, and more preferably, about 50% by weight when compared to thesulfur impurity of the heavy crude oil.

The catalytic processes described in embodiments herein are conducted atreduced temperatures thereby reducing the production cost by minimizingthe amount of steam that is used downhole. In some embodiments, thecatalysts may speed up the hydrogenation and oxidation processestherefore increasing production in less time.

In one embodiment, the heavy crude oil and a hydrogenating catalyticmaterial containing a nanocatalyst may be combined within the formation.The resulting nanocatalyst heavy oil mixture undergoes a catalytichydrogenation reaction once exposed to heat and a reducing agent or gas.In one example, a nanocatalyst-reducing agent mixture may be added intothe formation containing the heavy crude oil before or during the steamgeneration. The nanocatalyst-reducing agent mixture, once injected intothe formation and combined with the heavy crude oil, promotes convertingand upgrading the hydrocarbon downhole, in situ, including sulfurreduction. The in situ catalytic treatment process utilizing a reducingagent provides hydrovisbreaking, hydrocracking, hydrodesulfurizing, aswell as other hydrotreating processes to the heavy crude oil. Thereducing agent or reducing gas may contain hydrogen gas, carbonmonoxide, syngas or synthetic gas (e.g., a H₂/CO mixture), tetralin,decalin, derivatives thereof, or combinations thereof. The reducingagent may be gaseous, liquidized, or fluidized within the formation.Generally, the reducing agent may have a partial pressure of about 100psi or greater within the formation. In one example, the reducing agentcontains hydrogen gas, which has a partial pressure of about 100 psi orgreater within the formation.

In some examples, the catalytic material and the reducing agent or gasare co-flowed into the formation. In other examples, the catalyticmaterial and a carrier gas are co-flowed into the formation and thereducing agent or gas is separately transferred into the formation. Inother examples, the catalytic material, the reducing agent or gas, and acarrier gas are co-flowed into the formation.

The nanocatalyst may contain iron, nickel, molybdenum, tungsten,titanium, vanadium, chromium, manganese, cobalt, alloys thereof, oxidesthereof, sulfides thereof, derivatives thereof, or combinations thereof.In one example, the nanocatalyst contains iron and another metal, suchas nickel and/or molybdenum. In another example, the nanocatalystcontains a cobalt compound and a molybdenum compound. In anotherexample, the nanocatalyst contains a nickel compound and a molybdenumcompound. In another example, the nanocatalyst contains tungsten oxide,tungsten sulfide, derivatives thereof, or combinations thereof. Thecatalytic material may contain the catalyst supported onnanoparticulate, such as carbon nanoparticles, carbon nanotubes,alumina, silica, molecular sieves, ceramic materials, derivativesthereof, or combinations thereof. The nanoparticulate or thenanocatalysts usually have a diameter of less than 1 μm, such as withina range from about 5 nm to about 500 nm.

One embodiment of the invention employs nanocatalysts prepared in amanner, such as described in Enhancing Activity of Iron-based CatalystSupported on Carbon Nanoparticles by Adding Nickel and Molybdenum,Ungula Priyanto, Kinya Sakanishi, Osamu Okuma, and Isao Mochida,Preprints of Symposia: 220^(th) ACS National Meeting, Aug. 20-24, 2000,Washington, D.C. The catalyst may be transported into apetroleum-bearing formation by a carrier gas. The gas is a reducing gassuch as hydrogen and the catalyst is designed to promote an in situreaction between the reducing gas and the oil within the reservoir. Inorder for the conversion and upgrading reactions to occur in thereservoir, the catalyst, reducing gas, and the heavy oil or bitumen maybe in intimate contact at a temperature of at least about 400° F., andat a hydrogen partial pressure of at least about 100 psi. The intimatecontact, the desired temperature, and the desired pressure may bebrought about by a downhole steam generator, such as described incommonly assigned U.S. Pat. Nos. 6,016,867, 6,016,868, and 6,328,104,which are incorporated herein by reference in their entirety. The steam,nanocatalysts, and unburned reducing gases are forced into the formationby the pressure created by the downhole steam generator. Because thereducing gas may be the carrier for the nanocatalysts, these twocomponents will tend to travel together in the petroleum-bearingformation. Under the requisite heat and pressure, the reducing gasreacts with the heavy oil and bitumen thereby reducing its viscosity,lowering the sulfur impurity concentration, and increasing its APIgravity while producing lighter oil products.

In another embodiment, the heavy crude oil and an oxidizing catalyticmaterial containing a nanocatalyst may be combined within the formation.The resulting nanocatalyst heavy oil mixture undergoes a catalyticoxidation reaction once exposed to heat and an oxidizing agent or gas.In one example, a nanocatalyst-oxidizing agent mixture may be added intothe formation containing the heavy crude oil before or during the steamgeneration. The nanocatalyst-oxidizing agent mixture, once injected intothe formation and combined with the heavy crude oil, promotes convertingand upgrading the hydrocarbon downhole by decreasing the viscositythrough an oxidation reaction. The oxidizing agent or oxidizing gas maycontain a reagent, such as oxygen gas, air, oxygen enriched air,hydrogen peroxide solution, derivatives thereof, or combinationsthereof. In one example, the catalytic material and the oxidizing agentor gas are co-flowed into the formation. In another example, thecatalytic material and a carrier gas are co-flowed into the formationand the oxidizing agent or gas is separately transferred into theformation. In another example, the catalytic material, the oxidizingagent or gas, and a carrier gas are co-flowed into the formation.

In another embodiment, the catalytic material containing nanocatalyst isused to decrease the viscosity of the heavy crude oil during a catalyticoxidation process. The nanocatalyst may contain titanium, zirconium,aluminum, silicon, oxides thereof, alloys thereof, derivatives thereof,or combinations thereof. In one example, the nanocatalyst containstitanium oxide or a titanium oxide based material. In other examples,the nanocatalyst contains zirconium oxide, aluminum oxide, siliconoxide, alloys thereof, or combinations thereof. The catalytic materialmay contain the catalyst supported on nanoparticulate, such as carbonnanoparticles, carbon nanotubes, molecular sieves, alumina, silica,ceramic materials, derivatives thereof, or combinations thereof. Thenanoparticulate or the nanocatalysts usually have a diameter of lessthan 1 μm, such as within a range from about 5 nm to about 500 nm.

A carrier gas may be used to transport the catalytic material containingthe nanocatalyst to the heavy crude oil within the formation. Thecarrier gas may be a single gas or a mixture of gasses and may be any ofthe aforementioned reducing gases or oxidizing gases. Carrier gases thatmay be useful during the processes described herein include carbondioxide, hydrogen, syngas, air, oxygen, oxygen enriched air, carbonmonoxide, nitrogen, derivatives thereof, or combinations thereof.

In one example, carbon dioxide is used as a carrier gas and is exposedto the heavy crude oil and the catalytic material during the recoveryprocess. Carbon dioxide is used as an in situ viscosity reducing agent.The carbon dioxide may be transferred from outside of the formation,through a borehole, and into the formation, or alternatively, generatedby combusting a hydrocarbon within the formation. In another example, areducing gas, such as hydrogen gas or carbon monoxide, is used as acarrier gas during the recovery process. Generally, the reducing gas isutilized along with a hydrogenation nanocatalyst. In another example, anoxidizing gas, such as oxygen gas or air, is used as a carrier gasduring the recovery process. The oxidizing gas is generally utilizedalong with an oxidizing nanocatalyst.

In one embodiment, the carrier gas may be preheated on the surface priorto entering the borehole or a transfer vessel. The carrier gas may bepreheated using a heat source or heat exchange device. The carrier gasmay be preheated to a temperature of up to about 600° F., preferably,from about 450° F. to about 580° F. The preheated gas is supplied to thetransfer vessel at an elevated temperature that provides for heat lossesin the heat transfer vessel as well as the heavy crude oil within theformation and still be sufficient to maintain the in situ catalyticreactions for which the catalyst was designed.

In another embodiment, the carrier gas is not preheated on the surfaceprior to entering the borehole or the transfer vessel while notemploying a downhole steam generator. One or more electrical heaters maybe placed within or at the bottom of the wellbore in order to heat theheavy crude oil in the formation. The carrier gas is heated within theborehole and carries the heat via convection into the formation.

For other types of reactions, the carrier gas is one or more of thereactants. For example, if the reaction that is promoted is in situcombustion, the carrier gas is oxygen, rich air, or air. In anotherembodiment, carbon dioxide is the carrier gas for a cracking catalystthat promotes in situ cracking of the hydrocarbon in the formation.

In another example, the steam and heat are generated by combustingoxygen gas and hydrogen gas within the steam generator. The oxygen gasand the hydrogen gas may each be transferred from outside of theformation, through a borehole, and into the formation. In anotherexample, the steam, carbon dioxide, and heat are generated by combustingoxygen gas and a hydrocarbon gas within the steam generator. The oxygengas and the hydrocarbon gas may each be transferred from outside of theformation, through a borehole, and into the formation. The hydrocarbongas may contain methane.

In some examples, the nanocatalyst heavy oil mixture may be heatedwithin the formation by flowing heated gas, liquid, or fluid fromoutside of the formation, through a borehole, and into the formationwhile exposing the nanocatalyst heavy oil mixture. In one example, thenanocatalyst heavy oil mixture is exposed to heated water, steam, orcombinations thereof. In other examples, the nanocatalyst heavy oilmixture is heated within the formation by an electric heater positionedwithin the formation. In other examples, the method further includesheating the nanocatalyst heavy oil mixture within the formation bypositioning a steam generator within the formation, and generating andreleasing steam from the steam generator to heat the nanocatalyst heavyoil mixture within the formation.

In another embodiment, several interchangeable vessels are used toprepare and disperse the catalytic material. In one example, a carriergas is used to flow a first batch of a catalytic material from a firstvessel and into the formation containing the heavy crude oil where thenanocatalyst and the heavy crude oil form a nanocatalyst heavy oilmixture. Meanwhile, a second batch of the catalytic material is preparedwithin a second vessel. Once the first vessel is emptied of thecatalytic material, the carrier gas is rerouted to flow to the secondvessel, and the second batch of the catalytic material is transferredfrom the second vessel and into the formation containing the heavy crudeoil. Additional catalytic material may be prepared in the first vesselor the first vessel may be simply refilled with catalytic material.

FIG. 12 depicts nanocatalyst system 100 containing vessels 111 and 113according to another embodiment described herein. Nanocatalyst system100 may be used to prepare and transport catalytic material containingnanocatalysts. Vessels 111 and 113 may be positioned above ground withinthe vicinity of borehole 104. Borehole 104 extends through the ground toformation 106 containing heavy crude oil 108 or similar heavy petroleumreserves.

In one example, vessel 111 is in catalyst preparation mode and vessel113 is in transfer mode. When a catalyst preparation and transfer cycleis complete, the roles of vessels 111 and 113 are reversed. When vessel111 is in catalyst preparation mode, valves 115 and 117 may be closed.The precursors used to form catalytic materials may be added to vessel111 through separate ports, conduits, pipes, or lines. For example,vessel 111 may be charged with nanoparticles and a catalyst containingsolution or suspension may be transferred from source 110, through valve119, and into vessel 111. In another example, source 110 contains asolution of dissolved metal salts or compounds that have usefulcatalytic activity. Thereafter, valve 119 may be closed and the catalystmaterials may be mixed, heated, and dried within vessel 111. When thecatalyst preparation is complete, valves 115 and 117 are opened and thecarrier gas flows from carrier gas source 112, through vessel 111, tocarry the nanocatalyst particles through a feedline and into borehole104. Vessels 111 and 113 may each independently be heated by a heatingdevice, such as an electric heater.

Once vessel 111 is empty of the catalytic material, vessel 111 may beplaced in catalyst preparation mode and vessel 113 placed in transfermode. Valve 127 is closed, valves 123 and 125 are open, and the carriergas flows from carrier gas source 112, through vessel 113. Valve 127controls the transfer of catalyst preparation materials (not shown) intovessel 113, to carry the nanocatalyst particles through a feedline andinto borehole 104.

Steam generator 121 may be positioned within borehole 104 and used tosteam and heat heavy crude oil 108 within formation 106. Steam generator121 may be coupled to and in fluid communication with carrier gas source114, reducing agent source 116, oxidizing agent source 118, and steamsource 120.

When the cycle of catalyst preparation in one vessel and the catalysttransfer from the other vessel is complete, the roles of the two vesselsare reversed. The vessel where the catalyst was prepared becomes thetransfer vessel, and the vessel that had the catalyst transferred outbecomes the catalyst preparation vessel. This alternation of rolescontinues until the catalyst injection process is complete, such thatthe lighter oil products are formed and extracted from the formation.

Some catalysts contain a metal or a metal-containing compound disposedon a carbon nanotube. For those catalysts, the temperature of theupgrading reactions must be below the temperature that allows the steamto react with the carbon tubes. Other catalysts, such as titanium oxideor titanium oxide, are not affected by steam and are effective incatalyzing upgrading reactions.

Vessels 111, 113 may operate in parallel to prepare the nanocatalyst andtransfer the nanocatalyst to borehole 104. The vessels may be separatedfrom the continuous flow of reducing gas, oxidizing gas, and steam. Forexample, a nanocatalyst is prepared by impregnating a nickel compound orsalt and a molybdenum compound or salt on carbon nanoparticles resultingin a catalyst with about 2% by weight of nickel, about 10% by weight ofmolybdenum, and about 88% by weight of carbon nanoparticles. One type ofcarbon nanoparticles that may be used is KETJEN BLACK® nanoparticles,available from Akzo Nobel Chemicals BV. When the batch of catalyst isfinished and dried, the carrier gas is passed through thecatalyst-containing vessel thereby carrying the catalyst into theinjection well and then into the formation. While the catalyst that wasprepared in one vessel is being transferred to the lines leading to theinjection well, another batch of catalyst is prepared in the othervessel. The alternation of catalyst preparation and transfer iscontinued in each of the two vessels as long as the in situ processbenefits from use of the catalyst.

Recovery processes utilizing nanocatalyst, as described by embodimentsherein, provide many advantages to past processes. In one embodiment,the process includes bringing together a reducing agent (e.g., H₂), ahydrogenation catalyst, heavy crude oil in place, heat, and pressure,thereby causing catalytic reactions to occur within the reservoir. Inanother embodiment, the process includes bringing together an oxidizingagent (e.g., O₂), an oxidation catalyst, heavy crude oil in place, heat,and pressure, thereby causing catalytic reactions to occur within thereservoir.

Other embodiments provide many opportunities for in situ upgrading ofpetroleum products since a wide variety of nanocatalysts are available.The nature of catalysts is to promote reactions at milder conditions(e.g., lower temperatures and pressures) than thermal or non-catalyticreactions. Therefore, hydrogenation or oxidation, for example, may beconducted in situ at shallower depths than conventional pyrolysis andother thermal reactions. In one example, the catalytic processesdescribed herein may be performed within formations at a depth within arange from about 500 feet to about 5,000 feet.

Embodiments provide a platform technology that is applicable to a widerange of in situ reactions in a wide range of heavy oil, ultra-heavyoil, natural bitumen, and lighter deposits. The term “heavy crude oil,”as used herein, may include heavy oil, ultra-heavy oil, bitumen, as wellas other petroleum mixtures displaced underground within formations.

Furthermore, embodiments provide methods that have many applications,including in situ catalytic hydrogenation, in situ catalytichydrovisbreaking, in situ catalytic hydrocracking, in situ catalyticcombustion, in situ catalytic reforming, in situ catalytic alkylation,in situ catalytic isomerization, and other in situ catalytic refiningreactions.

While the foregoing is directed to embodiments of the invention, otherand further embodiments of the invention may be devised withoutdeparting from the basic scope thereof, and the scope thereof isdetermined by the claims that follow.

1. A method for recovering petroleum products from a petroleum-bearing formation, comprising: flowing a catalytic material comprising a nanocatalyst into a formation comprising a heavy crude oil; exposing the heavy crude oil and the catalytic material to a reducing agent; positioning a steam generator within the formation; generating and releasing steam from the steam generator to heat the heavy crude oil comprising the catalytic material; forming lighter oil products from the heavy crude oil within the formation; and extracting the lighter oil products from the formation.
 2. The method of claim 1, wherein the nanocatalyst comprises a metal selected from the group consisting of iron, nickel, molybdenum, tungsten, titanium, vanadium, chromium, manganese, cobalt, alloys thereof, oxides thereof, sulfides thereof, derivatives thereof, and combinations thereof.
 3. The method of claim 2, wherein the nanocatalyst comprises iron and a metal selected from the group consisting of nickel, molybdenum, tungsten, titanium, vanadium, chromium, manganese, cobalt, alloys thereof, oxides thereof, sulfides thereof, derivatives thereof, and combinations thereof.
 4. The method of claim 3, wherein the nanocatalyst comprises iron, nickel, and molybdenum.
 5. The method of claim 2, wherein the nanocatalyst comprises a nickel compound and a molybdenum compound.
 6. The method of claim 2, wherein the nanocatalyst comprises a cobalt compound and a molybdenum compound.
 7. The method of claim 2, wherein the nanocatalyst comprises tungsten oxide, tungsten sulfide, derivatives thereof, or combinations thereof.
 8. The method of claim 2, wherein the catalytic material comprises the nanocatalyst supported on carbon nanoparticulate.
 9. The method of claim 8, wherein the carbon nanoparticulate has a diameter of less than 1 μm.
 10. The method of claim 9, wherein the diameter is within a range from about 5 nm to about 500 nm.
 11. The method of claim 2, wherein the catalytic material comprises the nanocatalyst supported on alumina, silica, molecular sieves, ceramic materials, derivatives thereof, or combinations thereof.
 12. The method of claim 1, wherein the heavy crude oil comprising the catalytic material is heated by the steam to a temperature of less than about 600° F.
 13. The method of claim 12, wherein the temperature is within a range from about 250° F. to about 580° F.
 14. The method of claim 13, wherein the temperature is within a range from about 400° F. to about 550° F.
 15. The method of claim 1, wherein the reducing agent comprises a reagent selected from the group consisting of hydrogen gas, carbon monoxide, synthetic gas, tetralin, decalin, derivatives thereof, and combinations thereof.
 16. The method of claim 15, wherein the catalytic material and the reducing agent are co-flowed into the formation.
 17. The method of claim 16, wherein the reducing agent comprises hydrogen gas.
 18. The method of claim 17, wherein the hydrogen gas has a partial pressure of about 100 psi or greater within the formation.
 19. The method of claim 1, wherein the steam is generated by combusting oxygen gas and hydrogen gas within the steam generator.
 20. The method of claim 19, wherein the oxygen gas and the hydrogen gas are each transferred from outside of the formation, through a borehole, and into the formation.
 21. The method of claim 1, wherein the steam is generated by combusting oxygen gas and a hydrocarbon gas within the steam generator.
 22. The method of claim 21, wherein the oxygen gas and the hydrocarbon gas are each transferred from outside of the formation, through a borehole, and into the formation.
 23. The method of claim 22, wherein the hydrocarbon gas comprises methane.
 24. The method of claim 1, further comprising reducing viscosity of the heavy crude oil by exposing the heavy crude oil and the catalytic material to carbon dioxide.
 25. The method of claim 24, wherein the carbon dioxide is transferred from outside of the formation, through a borehole, and into the formation.
 26. The method of claim 1, wherein the lighter oil products comprise a lower concentration of a sulfur impurity than the heavy crude oil.
 27. The method of claim 26, wherein the lighter oil products comprise about 50% by weight or less of the sulfur impurity than the heavy crude oil.
 28. The method of claim 27, wherein the lighter oil products comprise about 30% by weight or less of the sulfur impurity than the heavy crude oil.
 29. A method for recovering petroleum products from a petroleum-bearing formation, comprising: flowing a catalytic material comprising a nanocatalyst into a formation comprising a heavy crude oil; exposing the heavy crude oil and the catalytic material to an oxidizing agent; positioning a steam generator within the formation; generating and releasing steam from the steam generator to heat the heavy crude oil comprising the catalytic material; forming lighter oil products from the heavy crude oil within the formation; and extracting the lighter oil products from the formation.
 30. The method of claim 29, wherein the nanocatalyst comprises a member selected from the group consisting of titanium, zirconium, aluminum, silicon, oxides thereof, alloys thereof, derivatives thereof, and combinations thereof.
 31. The method of claim 30, wherein the nanocatalyst comprises titanium oxide.
 32. The method of claim 30, wherein the catalytic material comprises the nanocatalyst supported on carbon nanotubes.
 33. The method of claim 30, wherein the catalytic material comprises the nanocatalyst supported on alumina, silica, molecular sieves, ceramic materials, derivatives thereof, or combinations thereof.
 34. The method of claim 29, wherein the heavy crude oil comprising the catalytic material is heated by the steam to a temperature of less than about 600° F.
 35. The method of claim 34, wherein the temperature is within a range from about 250° F. to about 580° F.
 36. The method of claim 35, wherein the temperature is within a range from about 400° F. to about 550° F.
 37. The method of claim 29, wherein the oxidizing agent comprises a reagent selected from the group consisting of oxygen gas, air, oxygen enriched air, hydrogen peroxide solution, derivatives thereof, and combinations thereof.
 38. The method of claim 37, wherein the catalytic material and the oxidizing agent are co-flowed into the formation.
 39. The method of claim 38, wherein the oxidizing agent comprises oxygen gas.
 40. The method of claim 29, wherein the steam is generated by combusting oxygen gas and hydrogen gas within the steam generator.
 41. The method of claim 40, wherein the oxygen gas and the hydrogen gas are each transferred from outside of the formation, through a borehole, and into the formation.
 42. The method of claim 29, wherein the steam is generated by combusting oxygen gas and a hydrocarbon gas within the steam generator.
 43. The method of claim 42, wherein the oxygen gas and the hydrocarbon gas are each transferred from outside of the formation, through a borehole, and into the formation.
 44. The method of claim 43, wherein the hydrocarbon gas comprises methane.
 45. The method of claim 29, further comprising reducing viscosity of the heavy crude oil by exposing the heavy crude oil and the catalytic material to carbon dioxide.
 46. The method of claim 45, wherein the carbon dioxide is transferred from outside of the formation, through a borehole, and into the formation.
 47. The method of claim 29, wherein the lighter oil products comprise a lower concentration of a sulfur impurity than the heavy crude oil.
 48. The method of claim 47, wherein the lighter oil products comprise about 50% by weight or less of the sulfur impurity than the heavy crude oil.
 49. The method of claim 48, wherein the lighter oil products comprise about 30% by weight or less of the sulfur impurity than the heavy crude oil.
 50. A method for recovering petroleum products from a petroleum-bearing formation, comprising: flowing a nanocatalyst and a reducing agent into a formation comprising a heavy crude oil, wherein the nanocatalyst and the heavy crude oil form a nanocatalyst heavy oil mixture; positioning a steam generator within the formation; generating and releasing steam from the steam generator to heat the nanocatalyst heavy oil mixture within the formation; forming lighter oil products by hydrogenating the heavy crude oil within the nanocatalyst heavy oil mixture; and extracting the lighter oil products from the formation.
 51. The method of claim 50, wherein the nanocatalyst comprises a metal selected from the group consisting of iron, nickel, molybdenum, tungsten, titanium, vanadium, chromium, manganese, cobalt, alloys thereof, oxides thereof, sulfides thereof, derivatives thereof, and combinations thereof.
 52. The method of claim 51, wherein the nanocatalyst comprises iron and a metal selected from the group consisting of nickel, molybdenum, tungsten, titanium, vanadium, chromium, manganese, cobalt, alloys thereof, oxides thereof, sulfides thereof, derivatives thereof, and combinations thereof.
 53. The method of claim 52, wherein the nanocatalyst comprises iron, nickel, and molybdenum.
 54. The method of claim 51, wherein the nanocatalyst comprises a nickel compound and a molybdenum compound.
 55. The method of claim 51, wherein the nanocatalyst is supported on carbon nanoparticulate.
 56. The method of claim 55, wherein the carbon nanoparticulate has a diameter of less than 1 μm.
 57. The method of claim 56, wherein the diameter is within a range from about 5 nm to about 500 nm.
 58. The method of claim 51, wherein the nanocatalyst is supported on alumina, silica, molecular sieves, ceramic materials, derivatives thereof, or combinations thereof.
 59. The method of claim 50, wherein the nanocatalyst heavy oil mixture is heated by the steam to a temperature of less than about 600° F.
 60. The method of claim 59, wherein the temperature is within a range from about 250° F. to about 580° F.
 61. The method of claim 60, wherein the temperature is within a range from about 400° F. to about 550° F.
 62. The method of claim 50, wherein the reducing agent comprises a reagent selected from the group consisting of hydrogen gas, carbon monoxide, synthetic gas, tetralin, decalin, derivatives thereof, and combinations thereof.
 63. The method of claim 62, wherein the nanocatalyst and the reducing agent are co-flowed into the formation.
 64. The method of claim 63, wherein the reducing agent comprises hydrogen gas.
 65. The method of claim 64, wherein the hydrogen gas has a partial pressure of about 100 psi or greater within the formation.
 66. The method of claim 50, wherein the steam is generated by combusting oxygen gas and hydrogen gas within the steam generator.
 67. The method of claim 66, wherein the oxygen gas and the hydrogen gas are each transferred from outside of the formation, through a borehole, and into the formation.
 68. The method of claim 50, wherein the steam is generated by combusting oxygen gas and a hydrocarbon gas within the steam generator.
 69. The method of claim 68, wherein the oxygen gas and the hydrocarbon gas are each transferred from outside of the formation, through a borehole, and into the formation.
 70. The method of claim 69, wherein the hydrocarbon gas comprises methane.
 71. The method of claim 50, further comprising reducing viscosity of the heavy crude oil by exposing the nanocatalyst heavy oil mixture to carbon dioxide.
 72. The method of claim 71, wherein the carbon dioxide is transferred from outside of the formation, through a borehole, and into the formation.
 73. The method of claim 50, wherein the lighter oil products comprise a lower concentration of a sulfur impurity than the heavy crude oil.
 74. The method of claim 73, wherein the lighter oil products comprise about 50% by weight or less of the sulfur impurity than the heavy crude oil.
 75. The method of claim 74, wherein the lighter oil products comprise about 30% by weight or less of the sulfur impurity than the heavy crude oil.
 76. A method for recovering petroleum products from a petroleum-bearing formation, comprising: flowing a carrier gas through a first vessel containing a first batch of a catalytic material comprising a nanocatalyst within a first vessel; preparing a second batch of the catalytic material within a second vessel; flowing the catalytic material and the carrier gas from the first vessel and into a formation comprising a heavy crude oil, wherein the nanocatalyst and the heavy crude oil form a nanocatalyst heavy oil mixture; exposing the nanocatalyst heavy oil mixture to a reducing agent; positioning a steam generator within the formation; generating and releasing steam from the steam generator to heat the nanocatalyst heavy oil mixture within the formation; forming lighter oil products by hydrogenating the heavy crude oil within the nanocatalyst heavy oil mixture; and extracting the lighter oil products from the formation.
 77. The method of claim 76, wherein the carrier gas comprises carbon dioxide.
 78. The method of claim 76, wherein preparing the second batch of the catalytic material further comprises combining the nanocatalyst and nanoparticulate within the second vessel.
 79. The method of claim 78, wherein the nanocatalyst comprises a metal selected from the group consisting of iron, nickel, molybdenum, tungsten, titanium, vanadium, chromium, manganese, cobalt, alloys thereof, oxides thereof, sulfides thereof, derivatives thereof, and combinations thereof.
 80. The method of claim 79, wherein the nanoparticulate comprises carbon, alumina, silica, molecular sieves, ceramic materials, derivatives thereof, or combinations thereof.
 81. The method of claim 80, wherein the nanoparticulate has a diameter of less than 1 μm.
 82. The method of claim 81, wherein the diameter is within a range from about 5 nm to about 500 nm.
 83. A method for recovering petroleum products from a petroleum-bearing formation, comprising: flowing a nanocatalyst and a reducing agent into a formation comprising a heavy crude oil, wherein the nanocatalyst and the heavy crude oil form a nanocatalyst heavy oil mixture; heating the nanocatalyst heavy oil mixture within the formation to a temperature of less than about 600° F.; forming lighter oil products by hydrogenating the heavy crude oil within the nanocatalyst heavy oil mixture; and extracting the lighter oil products from the formation.
 84. The method of claim 83, wherein heating the nanocatalyst heavy oil mixture within the formation further comprises flowing heated gas, liquid, or fluid from outside of the formation, through a borehole, and into the formation while exposing the nanocatalyst heavy oil mixture.
 85. The method of claim 84, wherein the nanocatalyst heavy oil mixture is exposed to heated water, steam, or combinations thereof.
 86. The method of claim 83, wherein the nanocatalyst heavy oil mixture is heated within the formation by an electric heater positioned within the formation.
 87. The method of claim 83, wherein heating the nanocatalyst heavy oil mixture within the formation further comprises: positioning a steam generator within the formation; and generating and releasing steam from the steam generator to heat the nanocatalyst heavy oil mixture within the formation.
 88. The method of claim 83, wherein the temperature is within a range from about 250° F. to about 580° F.
 89. The method of claim 88, wherein the temperature is within a range from about 400° F. to about 550° F. 